There are a number of textbooks available that describe the processes involved in drilling for oil and gas. Examples of such textbooks are “Petroleum Well Construction” by Economides, Watters and Dunn-Norman, John Wiley & Sons, West Sussex, UK, 1998; “Applied Drilling Engineering” by Bourgoyne, Jr., Chenevert, Millhelm and Young, Jr., SPE Textbook Series, Vol. 2, Society of Petroleum Engineers, Richardson, Tex., 1991; or “Drilling Technology—In Nontechnical Language” by S. Devereux, PennWell Corp., Tulsa, Okla., 1999. Reference may be made to these textbooks for an understanding of general drilling processes.
A drilling operation suitable for implementing the present invention is shown in FIG. 1. The drill rig 10 drives a drill string 20, which is composed of a large number of interconnected sections 30, called pipe joints. The bottom of the drill string is composed of heavy-weight pipe sections 40, called drill collars. In a typical drilling operation, the rig rotates the drill string and thus the bottom hole assembly (BHA) 50. The BHA 50 may contain various instrumentation packages, possibly a mud motor or a rotary-steerable tool, stabilizers, centralizers, drill collars and the drill bit 60. The drill string and all downhole components are hollow, allowing for drilling fluids to be pumped from the surface to the bit, with the drilling fluid returning to the surface in the outer annulus between the drill string and the formation for cleaning and re-circulation. The drill string 20 may contain additional sections of heavy-weight drill pipe and/or specialized equipment such as drilling jars.
The two most common drive systems are the rotary-table system and the top-drive system. The rotary-table system, shown in FIG. 1, engages the drill string through the kelly bushing 65 and the kelly 70, causing the drill string 20 to rotate while the kelly 70 is free to move up and down as the pipe is lowered into the ground or is lifted from the borehole. As the borehole deepens, pipe joints 30 are periodically added to the top of the drill string 20 by means of rotary shoulder connections that provide mechanical strength and hydraulic seals. A top-drive system does not require a kelly 70; instead, the entire drive mechanism moves up and down with the top end of the drill string 20. A top-drive system facilitates and accelerates the drilling process; however, it is also more expensive than a rotary-table system.
FIG. 2 shows a commonly used pipe joint 30 comprising a “box” tool joint 301 at the top, a long tubular pipe body 302 and a “pin” tool joint 303 at the bottom. A typical length for a pipe joint is 31 ft. Both pin 303 and box 301 are equipped with conical threads that, when joined, form a rotary connection. The two primary purposes of the connection are the transmission of mechanical forces such as torque, tension and compression between pipe joints 30 and to provide a liquid-tight metal-to-metal seal at the outer interface. The conical thread can be typically made-up by hand and is tightened using pipe tongs or motorized spinners, a process that puts the pin 303 under tension, the box 301 under compression and the metal seal interfaces 305 also under compression. This compressional load must exceed the tensional loads the seal experiences during bending and flexing in the hole to keep the metal-to-metal seal intact. The interior walls of the pipe joint 30 may be coated with a high-performance phenol-based epoxy compound. This compound is a high-quality dielectric insulator that inhibits corrosion of the metallic pipe and reduces friction losses in the fluid. The thickness of the applied dielectric film is about 10-12 mils (0.25-0.3 mm) Commercially available examples of such compounds are “TK-236” or “TK-34”, both available from Tuboscope, Houston, U.S.A.
The downhole instrumentation packages collect information about the drilling process, about the formations being drilled, and about the fluids contained in those formations. In current practice, most of this data is stored in memory and later retrieved after the instrumentation has been brought back to the surface. A very small and compressed amount of information, however, is typically sent in real time to the surface using one of the currently available telemetry systems. The amount of information available in real time on a typical drilling telemetry system used to be adequate in the early times of directional drilling. A few bits of information describing the bit orientation with respect to the earth's gravitational and magnetic fields are already useful for following a pre-defined well path. Today, however, commercially viable reservoirs tend to be much more complex than those exploited in the past and the recovery rates of the oil in place must be constantly increased to make the remaining hydrocarbon reservoirs last longer. This also means that well trajectories cannot be fully pre-defined based on seismic data or data from offset wells. Instead, well trajectories are more and more determined while a hole is being drilled and are fine-tuned literally on a foot-by-foot basis. To accomplish this task, a lot more formation evaluation data must be brought to the surface and must be studied and interpreted while drilling is progressing. The interpretation results may or may not require adjustments to the well trajectory, which are communicated back to the rig site. The rig equipment in turn communicates these adjustments to the downhole equipment. An example for a downhole imaging device that generates large amounts of formation evaluation data while a hole is being drilled is described in “Field Testing of an Advanced LWD Imaging Resistivity Tool,” by Prammer et al., SPWLA 48th Annual Logging Symposium, Austin, Tex., 2007. Since the drilling process is relatively slow and formation data can be compressed by the downhole electronics, a transmission rate along the drill string of about 100-1,000 bits/second (bps) is required. In addition, the command channel from the surface to the downhole instrumentation and the drilling system requires a transmission rate of approximately 1-100 bps.
Thus, it is a goal of the present invention to provide a downhole data transmission system that can uplink data from downhole to the surface at a rate of at least 100 bits/sec, but preferably also at rates of 1,000-100,000 bps, and that can downlink data from the surface at a rate of at least 10 bps, but preferably at a rate of 10-1,000 bps.
The need to transmit data from a downhole location reliably has been recognized for a very long time. See, for example, U.S. Pat. No. 2,000,716, granted to Polk in 1935. Since then, a plethora of communications systems have been proposed and implemented with varying success. The obvious approach, running a continuous electrical or optical cable between the downhole location and the surface, runs into operational problems because every time a pipe joint is added or removed from the drill string, the entire cable must be lifted from the string. To address this problem, Exxon Production Research Company developed a cable system where the cable is stored downhole and is paid out as needed. See also: Robinson, L. H.: “Exxon Completes Wireline Drilling Data Telemetry System,” Oil & Gas Journal, Apr. 14, 1980, pp. 137-148. However, the operational complications using long cables lead to a segmented-cable approach. The 1935 Polk patent falls into that category. Polk uses sections of an electrically insulating liner “ . . . which may be made of synthetic resin, varnished cambric, asphaltum or other suitable material.” Inside the insulating liner, Polk places metal tubes, which are electrically connected to each other by metal springs. Using the metallic drill pipe as the return conductor, an electrical circuit can be established and d.c. or a.c. signal currents can flow up and down the drill pipe. Liners, however, have a range of technical and economical shortcomings First, a typical 15,000-ft. drill string would require the installation of 500 30-ft. sections of liner, which would dramatically increase the capital expense for the drill string. Second, a feature like a thin-walled tube protruding from the box section of the rotary joint is not compatible with normal rig operations, in which heavy downhole components can swing laterally against each other during make-up and break-out, crushing any fragile elements that protrude and interfere with that motion.
Shell Development Company developed an electrical telemetry system based on modified pipe joints with electrical contact rings in the mating surfaces of each tool joint. A wire inside the pipe bore connects those contacts on each end. See Denison, E. B.: “High Data Rate Drilling Telemetry System”, Journal of Petroleum Technology, February 1979, pp. 155-163. Again, operational problems exist with these kinds of systems, as they tend to short out unless each connection is carefully cleaned and prepared with special, non-conductive “pipe dope”. U.S. Pat. No. 6,123,561 to Turner et al. or U.S. Pat. No. 7,156,676 to Reynolds also describe transmission systems that employ electrical contacts between pipe segments. However, these systems have in common that in order to communicate along the drill string many hundreds of individual elements would have to be connected in series and all must function in order for the entire system to be operational. Often, failure mechanisms in such electromechanical systems are intermittent and manifest themselves only under the severe temperatures, pressures and mechanical stresses encountered downhole. Therefore, systems as described in or similar to the '561 or '676 patents are usable only over short distances, e.g. between components of the BHA.
Thus, it is a goal of the present invention to provide a downhole data transmission system that does not require special handling over and beyond the normal care applied to rotary joints. In particular, the system should be compatible with the pipe dope compounds typically used in the oil drilling environment, e.g. zinc-based compounds. The system should further be able to tolerate typical amounts of dirt, mud residue and other deposits that may or may not be electrically conductive in and around the rotary connection and along the length of the tubular. The system should also be able to tolerate partial short circuits against ground that are inevitable if the drilling fluid is conductive.
Frustration with the reliability of downhole electrical connections led to the search for connector-less systems. U.S. Pat. No. 2,379,800, granted to Hare in 1945, describes transformer coupling at each pipe joint as well as an embodiment using telescoping condensers to provide capacitive coupling between pipe sections. U.S. Pat. No. 4,215,426 to Lord added an amplifier and a battery in each pipe joint to the transformer-based system. U.S. Pat. No. 4,605,268 to Meador, further refines the idea of transformer coupling by specifying small toroidal coils to transmit data across a rotary connection. U.S. Pat. No. 4,788,544 to Howard uses an instrumentation package within the backbored box section of a tool joint that is held captive by the pin nose of the mated tool joint and transmits data across the rotary connection using a magnetic field and a Hall sensor. Similarly, U.S. Pat. No. 7,400,262 to Chemali et al. uses an instrument package located in the backbored box of the rotary connection. In this case, information between instrument packages is exchanged acoustically using the pipe body as transmission medium. It is easy to see that an acoustic transceiver rigidly held captive between box and pin is inefficient in terms of converting electric into acoustic energy and vice versa. However, enough acoustic energy must be produced to clearly differentiate the signal against the acoustic noise background emanating from the bit and random locations along the drill string where contact with the wall is being made. Thus, any such device would consume large amounts of electric energy for very little transmission bandwidth, i.e. data throughput. The low bandwidth would render such a system as no or little improvement over existing data transmission systems, while the high power requirements would make it uneconomical to power such a device from batteries and unfeasible to power such devices by energy harvesting techniques as described in the Chemali patent. In addition, the large number of repeaters necessary, together with their electromechanical nature and the complete absence of redundancy, would make it nearly impossible for the Chemali system to function over a useful time frame during downhole deployment.
Another data transmission system with transformer coupling is known as “IntelliPipe”. See, for example, U.S. Pat. No. 6,670,880 to Hall et al., or Pixton, D.: “Very High-Speed Drill String Communications Network—Report #41229R06”, Novatek Engineering, Provo, Utah, March 2003, or Pixton, D.: “Very High-Speed Drill String Communications Network—Report #41229R14”, Novatek Engineering, Provo, Utah, June 2005. This system can be used only with a particular type of pipe connectors, known as double-shouldered tool joints. When pipe segments are joined, corresponding magnetic couplers embedded in the inner, secondary rotary connection shoulders make contact and form a closed magnetic circuit. Due to the necessity of special pipe and the difficult machining involved, such systems are very expensive. A typical “IntelliPipe” drill string that is 15,000 ft. long may contain 500 coaxial cables, 1,000 half-coupler elements, 1,000 connectors between magnetic couplers and coaxial cable, approximately 10-15 signal repeater sub-systems, and various interfaces.
In the context of downhole data transmission, even the apparently simple engineering problem of running an electric connection between the two ends of a pipe joint is surprisingly difficult. The “IntelliPipe” system (see the '880 Hall patent) uses a straight armored coaxial cable that is constantly kept under tension and is only anchored at the tool joints. The U.S. Pat. No. 4,788,544 Howard patent proposes a coiled cable. These solutions interfere with such basic oil field tasks as cleaning the bore of pipe joints. Drilling fluids can be aggressive chemicals, e.g. due to their high salinity, which can damage the pipe by corrosion. Any kind of crevice or discontinuity in the flow stream attracts clay and/or other solid deposits, which must be removed by wire brushes run inside the pipe. Left unattended, dirty pipe is easily pitted and corroded, which can lead to a fatal failure under load in the future. While drilling, fluid throughputs of 1,000 gal./min. are not uncommon, pumped through a bore of a few inches in diameter. These fluids typically carry 1%-20% solid contents that, due to their high speed, carry massive abrasive forces acting on every obstacle present in the flow cross section. Even high quality steel or alloyed materials can be quickly eroded in this environment.
Thus, it is a further goal of the present invention to provide a downhole data transmission system that does not interfere with the flow of drilling fluids; that maintains a smooth interior bore compatible with smooth, laminar flow; that is compatible with standard cleaning operations, and that keeps the mechanical integrity of the pipe joint intact.
A very different category of telemetry systems establishes a point-to-point connection between the downhole instrumentation and the surface using the pipe string, the drilling fluid column or the earth as transmission medium. Common to these systems is the very high signal attenuation between transmitter and receiver and consequently very low data rates, typically in the range 0.3-30 bps. A particular family of systems in this category uses pressure pulses that travel inside the pipe string through the drilling fluid (“mud”). See, for example, U.S. Pat. No. 3,713,089 to Clacomb. Teleco Oilfield Company developed the first commercially successful mud-pulse system. Also see: Seaton, P. et al.: “New MWD-Gamma System Finds Many Field Applications”, Oil & Gas Journal, Feb. 21, 1983, pp. 80-84. The achievable data rate of pressure-pulse systems under realistic conditions is about 15 bps and rapidly falls with long drill strings and/or compressible fluids such as oil-based muds (OBM).
Another system in the point-to-point category transmits an extremely low-frequency electromagnetic signal of a few Hertz from a downhole location to the surface. An example of such a system is described in U.S. Pat. No. 4,087,781 to Grossi et al. The data to be communicated is modulated onto the carrier signal. Problems with these systems are the very low data rate, the one-directionality of the transmission and failure to communicate near metallic casing and/or near certain earth formations such as salt domes.
A third type of point-to-point systems transmits mechanical signals such as torque pulses through the body of the drill pipe. An example can be found in U.S. Pat. No. 3,805,606 to Stelzer et al. Of the aforementioned systems, different implementations of pressure pulse communications are currently in commercial use as well as variants of extremely low-frequency electromagnetic telemetry. However, it is believed that no system using mechanical or acoustic signaling along the pipe string is in commercial operation at this time.
To summarize, the apparent simple problem of establishing a signal path along a drill string has been found to be a very difficult engineering problem. Of all systems that divide the communications path into segments corresponding to pipe joints, only “IntelliPipe” is in limited commercial use. Of all point-to-point transmission systems, only mud pulsing and extremely low-frequency electromagnetic communications have been fully developed. In principle, the segmented approach is much more appealing because, due to frequent signal amplification and restoration, much higher data rates can be achieved compared to the point-to-point approach. The segmented approach, however, suffers from high initial and capital costs and operational problems, mostly the lack of reliability.
It is a further goal of the present invention to enable reliable high-speed data transmission on existing pipe string hardware. There are millions of feet (meters) of drill pipe in operation worldwide. Systems like “IntelliPipe” require new pipe to be machined and instrumented to exacting specifications and cannot be retrofitted onto existing drill pipe of various provenance. A goal of the invention is adaptability to used drill pipe using only machining and coating operations that are available in many pipe-reconditioning shops worldwide.
It is another goal of the present invention to allow used pipe to be re-conditioned for use with the invention. Drill pipe is kept in operation for many years by periodically cleaning and reconditioning all surfaces and by re-cutting worn out threads.
It is perhaps an underappreciated fact that any segmented system will fail, no matter how reliable the individual component may be, given enough of such components connected in series. This fundamental problem can be better understood numerically. Consider an n-element data transmission system, where each element functions fault-free with a probability p throughout a single deployment interval (e.g., between going into and pulling out of a hole). FIG. 3 depicts schematically such a serial system. Assuming that the individual probabilities (lower-case) p are independent of each other, the probability (upper-case) P of the entire system to function without failure is:P(n,p)=pn.
This function is plotted in FIG. 4 for n from 1 to 10,000 for probabilities p of 0.99, 0.999 and 0.9999. The vertical line shows the typical case of n=1000. Clearly, even given the rather unrealistic reliability of p=0.9999 (1 failure in 10,000 deployments) for a single element, the entire signal chain will break down approximately once in every 10 deployments. Given that a downhole failure is likely to be a lost-time failure (LTF), a 10% chance of failure is considered poor reliability.
One goal of the present invention is a data transmission system that does not fail if a single element in a many-element configuration fails or if multiple elements at different locations fail during operation. Such functionality can be achieved by providing multiple data transmission elements that under normal conditions operate in parallel as shown in FIG. 5. In case of a failure of an element, a parallel element takes over the workload of the failed elements by increasing its own workload. In mathematical notation, m elements are connected in parallel for a total of n*m elements per system. If the failure probabilities 1−p of all elements are equal and uncorrelated, the probability for the system to function without interruption is given by:P(m,n,p)=[1−(1−p)m]n*m.
This function is shown in FIG. 6 for the singly-redundant case of m=2. Again, n ranges from 1 to 10,000 and p is 0.99, 0.999 and 0.9999. Such a system can be characterized as very reliable except for the poorest element reliability of 0.99. The next step to a doubly-redundant system with m=3 is shown in FIG. 7 and the corresponding probabilities are plotted in FIG. 8. As can be seen, such a system is in fact more reliable than its parts and other failure mechanisms, such as failures in the interfaces to the system, will determine the overall system reliability.
The implementation of the “crossovers” (see FIGS. 5 and 7), which are essential for the isolation of a failure from the rest of the system, requires careful consideration. On one hand, “tight” coupling between elements is desired to avoid signal losses as much as possible. Tight coupling schemes are electrical contacts, followed by magnetic coupling, such as used in “IntelliPipe”. On the other hand, the coupling should be as weak as possible so that a failed system does not interfere with the functionality of the remaining system. These considerations lead to the conclusion that, in a rather counterintuitive way, “weak” coupling schemes can provide the path to high system redundancy and reliability.
It is thus a further goal of the present invention to achieve a high level of system reliability by implementing a serial/parallel transmission scheme in which single-point failures can be isolated and bypassed without deterioration in overall system functionality.
It is yet another goal of the present invention that the system can detect, diagnose and report all failures or problems as soon as they occur. An operator may choose to replace the affected drill string segment at the next opportunity. Such an opportunity may exist when the drill string must be removed from the hole, due to, for example, a worn-out drill bit.
It is still another goal of the present invention to provide the necessary information in an easy-to-understand format that does not require specialized knowledge about the inner workings of the system. Since the present invention employs a large number of instrumented data repeaters, it is straightforward to include diagnostic and recovery capabilities that are distributed throughout the system. These capabilities include the capability to sense a local hardware failure and to report that failure to the surface. Such a report contains the serial number of the affected pipe segment, which simplifies the replacement of that segment with one that is known to be working. A hardware failure may be sensed by a drop in received signal strength or transmission silence during a time interval in which a signal is to be expected. The recovery capabilities include the capability to take over the workload of a failed element by a working element that increases its duty cycle to compensate for the increased workload.
Another goal of the present invention is a data transmission system that can be adapted to a variety of drill pipes, drill pipe parts and various downhole and surface equipment. This should include transmission between components or parts of components that move relative to each other such as axial translation or rotation.
Yet another goal of the present invention is the provisioning of full bidirectional data transfer between terminals at the surface and downhole.
Still another goal of the present invention is the provisioning of data transmission in both directions that appears error-free between end points, such that “soft”, i.e. transient, errors are detected and corrected within the system.
It is a further goal of the present invention to provision a flexible-cost data transmission system. In certain applications, such as drilling through well-known formations, only a modest amount of data is required. In other applications, such as drilling an exploratory well or steering a steerable drill bit through a complicated reservoir zone, a high amount of data is required. Another example of a highly variable user dataflow is seismic-while-drilling (SWD). In SWD, seismic microphones and the associated electronics are part of the downhole instrumentation package. At times when drilling stops, such as when a new connection is made up, a seismic wave may be launched from the surface, which is recorded downhole. These waveforms may be sent to the surface in bursts and in real time using the data transmission system. Therefore, the data transmission system should preserve its resources during times when only a small amount of data is relevant and should transmit at high speed at times when large amounts of data are available and are relevant for real time operations.
It has been a long-accepted limitation of while-drilling measurements that data can only be gathered in the BHA, where typically all sensors are located. Thus, data along the borehole is only available shortly after a particular section has been drilled, while changes in that section that occur hours or days after the section has been drilled are not detectable. Such changes may include the influx of formation fluid into the borehole, a condition that depends among other factors on formation pressure, borehole pressure and the formation of mud cake on the borehole wall. Such influx is typically detectable as local temperature aberration because the borehole fluid and the formation fluids typically have different temperatures. It is also highly desirable to measure borehole pressure along the entire wellbore in order to equalize the pressure exerted by the formation towards the borehole, without applying too much pressure outwards, a situation that could ruin future production from a reservoir. Currently, the pressure and temperature profiles are simply estimated by linearly interpolation between surface values and BHA values, or worse, are calculated from assumed gradients. The “IntelliPipe” system has introduced limited capabilities to deploy sensors along the borehole in the signal repeaters. The “IntelliPipe” signal repeaters, however, are complex electronics packages that are spaced out as far as possible 1,000-2,000 ft. intervals along the drill string. Such course sampling is undesirable for gathering data along the entire wellbore.
Thus it is another goal of the current invention to enable data gathering along the wellbore with spacings between sensor points of as little as a single pipe joint, i.e. about 10 meters.